Friction reducing additives including nanoparticles

ABSTRACT

Compositions and methods for use in fracturing treatments using friction reducing additives that include nanoparticles are provided. In some embodiments, the methods include: providing a treatment fluid that includes an aqueous base fluid and a friction reducing additive, the friction reducing additive including at least one polymer and a plurality of nanoparticles; and introducing the treatment fluid into a portion of a subterranean formation at or above a pressure sufficient to create or enhance at least one fracture in the subterranean formation.

BACKGROUND

The present disclosure relates to compositions and methods for treatingsubterranean formations.

Wells in hydrocarbon-bearing subterranean formations may be stimulatedto produce those hydrocarbons using hydraulic fracturing treatments. Inhydraulic fracturing treatments, a viscous fluid (e.g., fracturing fluidor pad fluid) is pumped into a subterranean formation at a sufficientlyhigh rate and/or pressure (e.g., above the fracture gradient of theformation) such that one or more fractures are created or enhanced inthe formation. These fractures provide conductive channels through whichfluids in the formation such as oil and gas may flow to a well bore forproduction. In order to maintain sufficient conductivity through thefracture, it is often desirable that the formation surfaces within thefracture or “fracture faces” be able to resist erosion and/or migrationto prevent the fracture from narrowing or fully closing. Typically,proppant particulates suspended in a portion of the fracturing fluid arealso deposited in the fractures when the fracturing fluid is convertedto a thin fluid to be returned to the surface. These proppantparticulates serve to prevent the fractures from fully closing so thatconductive channels are formed through which produced hydrocarbons canflow.

In some conventional fracturing treatments, large amounts of water orother fluids (e.g., an average of 1 million gallons per fracturingstage) are pumped at high rates and pressures in order providesufficient energy downhole to form fractures in the formation of thedesired geometries. To create fractures in certain types of formations(e.g., unconventional formations or low permeability formations) or tocreate complex fracture network in subterranean formations, operatorsmay rely on the use of a low viscosity fluid (e.g., slickwater fluids)as the main fracturing fluid and small size proppant (e.g., 100-mesh) asthe proppant. During the placement of aqueous fracturing fluids into awellbore, a considerable amount of energy may be lost due to frictionbetween the treatment fluid in turbulent flow and the formation and/ortubular goods (e.g., pipes, coiled tubing, etc.) disposed within thewell bore. As a result of these energy losses, additional horsepower maybe necessary to achieve the desired treatment. To reduce these energylosses, friction reducing polymers are typically included in aqueoustreatment fluids.

BRIEF DESCRIPTION OF THE DRAWINGS

These drawings illustrate certain aspects of some of the embodiments ofthe present disclosure, and should not be used to limit or define theclaims.

FIG. 1 is a diagram illustrating an example of a fracturing system thatmay be used in accordance with certain embodiments of the presentdisclosure.

FIG. 2 is a diagram illustrating an example of a subterranean formationin which a fracturing operation may be performed in accordance withcertain embodiments of the present disclosure.

While embodiments of this disclosure have been depicted, suchembodiments do not imply a limitation on the disclosure, and no suchlimitation should be inferred. The subject matter disclosed is capableof considerable modification, alteration, and equivalents in form andfunction, as will occur to those skilled in the pertinent art and havingthe benefit of this disclosure. The depicted and described embodimentsof this disclosure are examples only, and not exhaustive of the scope ofthe disclosure.

DESCRIPTION OF CERTAIN EMBODIMENTS

The present disclosure relates to compositions and methods for treatingsubterranean formations. More particularly, the present disclosurerelates to compositions and methods for use in fracturing treatmentsusing friction reducing additives that include nanoparticles.

The present disclosure provides friction reducing additives that includeat least one polymer and a plurality of nanoparticles, and associatedmethods of use in subterranean fracturing treatments. The methods of thepresent disclosure generally include: providing a treatment fluid thatincludes an aqueous base fluid and a friction reducing additive, thefriction reducing additive including at least one polymer and aplurality of nanoparticles; and introducing the treatment fluid into aportion of a subterranean formation at or above a pressure sufficient tocreate or enhance at least one fracture in the subterranean formation.While not limiting the present disclosure or claims to any particularmechanism of action, In some embodiments, the nanoparticles may interactor associate with molecules of the polymer (e.g., via hydrogen bonding,hydrophobic association, covalent bonding, ionic associations, etc.) toenhance the degree to which the polymer is able to reduce friction asthe treatment fluid is pumped, flowed, or otherwise introduced into asubterranean formation.

Among the many potential advantages to the methods and compositions ofthe present disclosure, only some of which are alluded to herein, themethods and compositions of the present disclosure may exhibit enhancedviscosity in treatment fluids used in fracturing, particularly ascompared with certain conventional friction reducing systems andadditives. In some embodiments, the friction reducing additives of thepresent disclosure may viscosity a treatment fluid to a desired degreeusing less polymeric additives than would be necessary for certainconvention friction reducing polymers to provide the same increase ofviscosity. This may, among other benefits, result in less plugging, rockwettability alteration, and/or damage in the formation, as well as moreeffective stimulation of the formation. In some embodiments, thetreatment fluids and/or friction reducing additives of the presentdisclosure may not require the presence of crosslinkers to achieve thedesired levels of viscosity and/or friction reduction. In someembodiments, the friction reducing additives of the present disclosuremay be effective in brines, brackish water, and/or produced waterdespite the presence of ionic species or large amounts of dissolvedsolids (e.g., high total dissolved solids (TDS) fluids) therein.

The polymers in the friction reducing additives of the presentdisclosure may include any cationic, anionic, non-ionic, and/oramphoteric polymer, or any combination thereof. As used herein, unlessthe context otherwise requires, a “polymer” includes homopolymers,copolymers, terpolymers, etc. In addition, the term “copolymer” as usedherein is not limited to the combination of polymers having twomonomeric units, but includes any combination of monomeric units, forexample, terpolymers, tetrapolymers, etc. The polymers are generallywater-based linear polymers that are not crosslinked by a crosslinkingagent. Examples of polymers that may be suitable include, but are notlimited to, polyacrylamide, polyacrylamide derivatives, polyacrylamideco-polymers, polyethylene oxide, polypropylene oxide, a copolymer ofpolyethylene and polypropylene oxide, polysaccharides (e.g., guar, guarderivatives, cellulose, cellulose derivatives (e.g.,hydroxyethylcellulose)), biopolymers, and any combination thereof. Insome embodiments, a polymer including acrylamide may be a cationic,anionic, non-ionic, and/or amphoteric polymer, or any combinationthereof. In some embodiments, a polymer including acrylamide may be apartially hydrolyzed acrylamide. As used in this disclosure, “partiallyhydrolyzed acrylamide” refers to acrylamide wherein in the range of fromabout 3% to about 70% of the amide groups have been hydrolyzed tocarboxyl groups. Polyacrylamide copolymers generally include polymers ofacrylamide with one or more additional monomers. Examples of suchadditional monomers may include, but are not limited to acrylic acid,acrylic acid ester, methacrylic acid, methacrylic acid ester, acrylates,2-acrylamido-2-methylpropane sulfonic acid,2-acrylamido-tertbutylsulfonic acid, N,N-dimethylacrylamide, vinylsulfonic acid, N-vinyl acetamide, N-vinyl formamide, itaconic acid,methacrylic acid, diallyl dimethyl ammonium chloride, and anycombination thereof.

In some embodiments, the polymers may include certain multifunctionalpolymer additives that having releasable choline groups or releasablepoly(diallyldimethylammonium chloride) (polyDADMAC) groups in thepolymer backbone. In some embodiments, such polymers may include one ormore cationic block copolymers of diallyldimethylammonium chloride(DADMAC) or at least one monomer selected from: a (trimethylamino)ethylacrylate and/or a (trimethylamino)ethyl methacrylate or any saltsthereof (e.g., (trimethylamino)ethyl acrylate methyl chloride quaternarysalt, (trimethylamino)ethyl acrylate methyl sulfate quaternary salt,(trimethylamino)ethyl acrylate benzyl chloride quaternary salt,(trimethylamino)ethyl acrylate sulfuric acid salt, (trimethylamino)ethylacrylate hydrochloric acid salt, (triethylamino)ethyl acrylate methylchloride quaternary salt, (trimethylamino)ethyl methacrylate methylchloride quaternary salt, (trimethylamino) ethyl methacrylate methylsulfate quaternary salt, (trimethylamino)ethyl methacrylate benzylchloride quaternary salt, (trimethylamino)ethyl methacrylate sulfuricacid salt, (trimethylamino)ethyl methacrylate hydrochloric acid salt,(trimethylamino)ethyl methacryloyl hydrochloric acid salt), or acombination thereof. In some embodiments, such polymers may include apoly(acrylamide-co-dimethylaminoethyl acrylate) quaternary ammoniumchloride salt.

Those of ordinary skill in the art will appreciate that the polymer(s)included in the treatment fluid should have a molecular weightsufficient to provide a desired level of friction reduction. In general,polymers having higher molecular weights may be needed to provide adesirable level of friction reduction. In certain embodiments, thepolymer has a molecular weight in the range of about 5,000 Daltons(“Da”) to about 999,000,000 Da. In other embodiments, the polymer has amolecular weight in the range of about 1,000,000 Da to about 50,000,000Da. In other embodiments, the polymer has a molecular weight in therange of about 3,000,000 Da to about 10,000,000 Da. Those of ordinaryskill in the art will recognize that friction-reducing polymers havingmolecular weights outside the listed range may still provide some degreeof friction reduction.

The polymers may be present in a treatment fluid in an amount sufficientto provide a desirable level of friction reduction. In certainembodiments, the polymer is present in a treatment fluid in an amountsufficient to maintain laminar flow when the treatment fluid is pumpedinto the well bore and/or subterranean formation. For example, in someembodiments, the polymer may be present in the treatment fluid in anamount of from about 0.1 to about 100 gallon per thousand gallons offluid (“gpt”). In some embodiments, the polymer may be present in thetreatment fluid in an amount of from about 0.1 to about 5 gpt, or inother embodiments, from about 0.500 to about 2 gpt. In some embodiments,the polymer may be present in the treatment fluid in an amount of lessthan about 3 gpt, or alternatively, less than about 2 gpt. In certainembodiments, an amount of polymer on the higher end of the above rangesmay be desired, among other reasons, to impart adequate viscosity to thefluid. In certain embodiments, the treatment fluids of the presentdisclosure may have a total polymer concentration of less than 3 gpt, oralternatively, less than about 2 gpt.

The nanoparticles in the friction reducing additives of the presentdisclosure may include any solid particles having one or more dimensionsof about 1000 nm or less, or alternatively, about 100 nm or less, oralternatively, about 50 nm or less. In some embodiments, thenanoparticles for use in conjunction with the present disclosure mayhave a size with at least one dimension ranging from a lower limit ofabout 0.5 nm, 1 nm, 2 nm, 5 nm, 10 nm, or 25 nm to an upper limit ofabout 500 nm, 400 nm, 250 nm, or 100 nm and wherein the size in at leastone dimension may range from any lower limit to any upper limit andencompass any subset therebetween. The nanoparticles may be hydrophobicor hydrophilic, and may be made of any known material, including but notlimited to silica, graphene, metals (e.g., aluminum, iron, titanium,zinc), alkaline earth metals, metal oxides, boron, laponite, hydroxides,polymers, carbon, clay, composite materials, and any combination ormixture thereof. In some embodiments, the nanoparticles may includenanotubes, such as clay nanotubes (e.g., halloysite), carbon nanotubes,or the like. In some embodiments, the surface of the nanoparticles maybe chemically modified or functionalized (e.g., have another compoundedgrafted onto its surface), and/or the hydrophobicity or hydrophilicityof the nanoparticle may be modified by another chemical agent. Forexample, a silica nanoparticle (which typically would be hydrophilic)may be modified with a chemical agent such as a siloxane, a silane, or afluorocarbon to make the surface of the nanoparticle hydrophobic. Inother embodiments, the nanoparticles may be unmodified and/orunfunctionalized. The nanoparticles may be provided in any suitableform, e.g., as dry solids or may be provided in a liquid suspension orslurry with a carrier fluid.

The nanoparticles may be present in a treatment fluid in an amountsufficient to provide a desirable level of viscosity in conjunction withthe polymer discussed above. The nanoparticles may be present in ahigher or lower concentration than, or the same concentration as, thepolymer discussed above. In some embodiments, the nanoparticles may bepresent in the treatment fluid in amount of from about 0.01% to about 5%by volume of the treatment fluid. In some embodiments, the nanoparticlesmay be present in the treatment fluid in amount of from about 0.1% toabout 3% by volume of the treatment fluid, or in other embodiments, fromabout 0.5% to about 2% by volume of the treatment fluid. In someembodiments, the nanoparticles may be present in the treatment fluid inamount of about 1% by volume of the treatment fluid.

The treatment fluids used in the methods and compositions of the presentdisclosure may include any aqueous base fluid known in the art and anycombinations thereof. The term “base fluid” refers to the majorcomponent of the fluid (as opposed to components dissolved and/orsuspended therein), and does not indicate any particular condition orproperty of that fluids such as its mass, amount, pH, etc. Aqueousfluids that may be suitable for use in the methods and systems of thepresent disclosure may include water from any source. Such aqueousfluids may include fresh water, salt water (e.g., water containing oneor more salts dissolved therein), brine (e.g., saturated salt water),brackish water, seawater, produced water (e.g., water produced from thesame formation where the method of the present disclosure is beingconducted), or any combination thereof. In most embodiments of thepresent disclosure, the aqueous fluids include one or more ionicspecies, such as those formed by salts dissolved in water. For example,seawater and/or produced water may include a variety of divalentcationic species dissolved therein. In certain embodiments, the densityof the aqueous fluid can be adjusted, among other purposes, to provideadditional particulate transport and suspension in the compositions ofthe present disclosure. In certain embodiments, the pH of the aqueousfluid may be adjusted (e.g., by a buffer or other pH adjusting agent) toa specific level, which may depend on, among other factors, the types ofpolymers, nanoparticles, and/or other additives included in the fluid.One of ordinary skill in the art, with the benefit of this disclosure,will recognize when such density and/or pH adjustments are appropriate.In certain embodiments, the treatment fluids may include a mixture ofone or more base fluids and/or gases, including but not limited toemulsions, foams, and the like.

In some embodiments, the friction reducing additives and/or treatmentfluids of the present disclosure optionally may include at least onesurfactant, which may act as a compatibility agent and/or dispersionaid, e.g., to facilitate mixing and/or dispersing the nanoparticlesthroughout the fluid. The surfactants may include any known surfactant,and may be cationic, anionic, nonionic, or amphoteric. Types of cationicsurfactants that may be suitable for certain embodiments include, butare not limited to, alkyl amines, alkyl amine salts, quaternary ammoniumsalts such as trimethyltallowammonium chloride, amine oxides,alkyltrimethyl amines, triethyl amines, alkyldimethylbenzylamines,alkylamidobetaines such as cocoamidopropyl betaine, alpha-olefinsulfonate, C8 to C22 alkylethoxylate sulfate, trimethylcocoammoniumchloride, derivatives thereof, and combinations thereof. Types ofanionic surfactants that may be suitable for certain embodiments of thepresent disclosure include, but are not limited to, alkyl carboxylates,alkylether carboxylates, N-acylaminoacids, N-acylglutamates,N-acylpolypeptides, alkylbenzenesulfonates, paraffinic sulfonates,α-olefinsulfonates, lignosulfates, derivatives of sulfosuccinates,polynapthylmethylsulfonates, alkyl sulfates, alkylethersulfates,monoalkylphosphates, polyalkylphosphates, fatty acids, alkali salts ofacids, alkali salts of fatty acids, alkaline salts of acids, sodiumsalts of acids, sodium salts of fatty acid, alkyl ethoxylate, soaps,derivatives thereof, and combinations thereof. Types of non-ionicsurfactants that may be suitable for certain embodiments of the presentdisclosure include, but are not limited to, alcohol oxylalkylates, alkylphenol oxylalkylates, nonionic esters such as sorbitan estersalkoxylates of sorbitan esters, castor oil alkoxylates, fatty acidalkoxylates, lauryl alcohol alkoxylates, nonylphenol alkoxylates,octylphenol alkoxylates, and tridecyl alcohol alkoxylates. The selectionof a suitable surfactant may depend on several factors that would berecognized by a person of skill in the art with the benefit of thisdisclosure, including but not limited to the type of polymer in thefriction reducing additive, the characteristics of the base fluid (e.g.,pH, salinity, etc.), and the like. In some embodiments, certainsurfactants may exhibit certain synergistic effects with the polymer inthe friction reducing additive, which may enhance the degree to whichthe polymer is able to reduce friction and/or increase viscosity. Incertain embodiments, some such surfactants may enhance the viscosity ofthe treatment fluid. When used, the surfactant may be mixed with theother components of the friction reducing additive before it is mixedinto the treatment fluid. Alternatively, the surfactant may be added tothe treatment fluid separately from (before, after, or concurrentlywith) either or both of the polymer and/or nanoparticles. In otherembodiments, the treatment fluids of the present disclosure may besubstantially or entirely free of surfactants.

In certain embodiments, the friction reducing additives and/or treatmentfluids used in the methods and systems of the present disclosureoptionally may include any number of additional additives. Examples ofsuch additional additives include, but are not limited to, salts,surfactants, acids, proppant particulates (including microproppants),diverting agents, fluid loss control additives, gas, nitrogen, carbondioxide, surface modifying agents, tackifying agents, foamers, corrosioninhibitors, scale inhibitors, catalysts, clay control agents, biocides,additional friction reducers, antifoam agents, bridging agents,flocculants, additional H₂S scavengers, CO₂ scavengers, oxygenscavengers, lubricants, viscosifiers, breakers, weighting agents,relative permeability modifiers, resins, wetting agents, coatingenhancement agents, filter cake removal agents, antifreeze agents (e.g.,ethylene glycol), and the like. A person skilled in the art, with thebenefit of this disclosure, will recognize the types of additives thatmay be included, or should not be included, in the fluids of the presentdisclosure for a particular application. For example, in someembodiments, the fluids of the present disclosure may be substantiallyor entirely free of crosslinking agents, viscoelastic surfactants,and/or any of the other optional additives listed above.

The treatment fluids of the present disclosure may be prepared using anysuitable method and/or equipment (e.g., blenders, mixers, stirrers,etc.) known in the art at any time prior to their use. The treatmentfluids may be prepared at least in part at a well site or at an offsitelocation. In certain embodiments, the polymers, nanoparticles, and/orother components of the treatment fluid may be metered directly into abase treatment fluid to form a treatment fluid. In certain embodiments,the base fluid may be mixed with the polymers, nanoparticles, and/orother components of the treatment fluid at a well site where theoperation or treatment is conducted, either by batch mixing orcontinuous (“on-the-fly”) mixing. The term “on-the-fly” is used hereinto include methods of combining two or more components wherein a flowingstream of one element is continuously introduced into a flowing streamof another component so that the streams are combined and mixed whilecontinuing to flow as a single stream as part of the on-going treatment.Such mixing can also be described as “real-time” mixing. In otherembodiments, the treatment fluids of the present disclosure may beprepared, either in whole or in part, at an offsite location andtransported to the site where the treatment or operation is conducted.In introducing a treatment fluid of the present disclosure into aportion of a subterranean formation, the components of the treatmentfluid may be mixed together at the surface and introduced into theformation together, or one or more components may be introduced into theformation at the surface separately from other components such that thecomponents mix or intermingle in a portion of the formation to form atreatment fluid. In either such case, the treatment fluid is deemed tobe introduced into at least a portion of the subterranean formation forpurposes of the present disclosure. In some embodiments, the variouscomponents of the friction reducing additives and/or treatment fluids ofthe present disclosure may be mixed into the treatment fluid during somestages but not others. For example, the friction reducing additiveincluding the polymer and nanoparticles may be continuously mixed intothe treatment fluid, while the optional surfactant is only added inselected stages, among other reasons, to enhance the viscosity and/orother properties of the fluid only during those stages. In otherembodiments, the friction reducing polymer (e.g., a single part frictionreducer) may be continuously mixed into the treatment fluid, while thenanoparticles (and, optionally, the surfactant) is only added (e.g., toform a two-part friction reducing system) in selected stages, amongother reasons, to enhance the viscosity and/or other properties of thefluid only during those stages.

The components of the friction reducing additive may be provided in anysuitable fashion. In some embodiments, the polymer and nanoparticles maybe provided together (either by themselves or with other optionalcomponents such as solvents and/or carrier fluids) and then mixed withthe base fluid (and optionally other components) substantiallysimultaneously to form a treatment fluid of the present disclosure. Inother embodiments, the polymer and the nanoparticles of the frictionreducing additive may be mixed into the base fluid separately (eithersubstantially simultaneously or at different times), which would beunderstood to form a friction reducing additive of the presentdisclosure. When added separately, the relative amounts and/or ratios ofthe polymer and the nanoparticles added to the treatment fluid may bevaried throughout a particular fracturing operation. The polymer,nanoparticles, and/or surfactant also may be mixed into the treatmentfluid in any order and at any place in the mixing or fracturingequipment used in a particular application of the present disclosure.For example, in some embodiments, the nanoparticles can be mixed intothe fluid at the same injection point as the polymer (e.g., eye of thedischarge pump on a fracturing blender), or may be added to the fluidupstream or downstream of that injection point.

The present disclosure in some embodiments provides methods for usingthe treatment fluids to carry out hydraulic fracturing treatments(including fracture acidizing treatments). In certain embodiments, atreatment fluid may be introduced into a subterranean formation. In someembodiments, the treatment fluid may be introduced into a well bore thatpenetrates a subterranean formation. In some embodiments, the treatmentfluid may be introduced at a pressure sufficient to create or enhanceone or more fractures within the subterranean formation. The treatmentfluids used in these fracturing treatments may include a number ofdifferent types of fluids, including but not limited to pre-pad fluids,pad fluids, fracturing fluids, slickwater fluids, proppant-laden fluids,and the like. In some embodiments, the treatment fluids of the presentdisclosure may have a viscosity of about 50 cP or less, oralternatively, about 25 cP or less, or alternatively, about 15 cP orless. In some embodiments, the treatment fluids of the presentdisclosure may have a viscosity of from about 4 cP to about 15 cP at ashear rate of 511 s⁻¹. In other embodiments, the treatment fluids of thepresent disclosure may have higher viscosities, e.g., up to about 1000cP.

In certain embodiments, the viscosity of the treatment fluids of thepresent disclosure may be significantly reduced (e.g., to a level ofabout 1.5 cP or less) after a certain period of time, among otherreasons, to facilitate pumping and/or flowback of the fluids after use.In some embodiments, the viscosity of the treatment fluids may bereduced by the addition or activation of a breaker additive (e.g., anacid or other chemical agent that may degrade the polymer), or whensubjected to certain amounts of shear, heat, or other conditions. Insome embodiments, the viscosity of the treatment fluid may decreaseafter the passage of sufficient time (e.g., within 24 hours, within 4hours at temperatures of 140° F., or within about 0.5 hours attemperatures of 140° F.) without the addition of any breaker additivesthereto or change of conditions.

Certain embodiments of the methods and compositions disclosed herein maydirectly or indirectly affect one or more components or pieces ofequipment associated with the preparation, delivery, recapture,recycling, reuse, and/or disposal of the disclosed compositions. Forexample, and with reference to FIG. 1, the disclosed methods andcompositions may directly or indirectly affect one or more components orpieces of equipment associated with an exemplary fracturing system 10,according to one or more embodiments. In certain instances, the system10 includes a fracturing fluid producing apparatus 20, a fluid source30, an optional proppant source 40, and a pump and blender system 50 andresides at the surface at a well site where a well 60 is located. Incertain instances, the fracturing fluid producing apparatus 20 combinesa gel pre-cursor with fluid (e.g., liquid or substantially liquid) fromfluid source 30, to produce a hydrated fracturing fluid that is used tofracture the formation. The hydrated fracturing fluid can be a fluid forready use in a fracture stimulation treatment of the well 60 or aconcentrate to which additional fluid is added prior to use in afracture stimulation of the well 60. In other instances, the fracturingfluid producing apparatus 20 can be omitted and the fracturing fluidsourced directly from the fluid source 30. In certain instances, thefracturing fluid may include water, a hydrocarbon fluid, a polymer gel,foam, air, wet gases and/or other fluids.

The proppant source 40 can include a proppant for combination with thefracturing fluid. The system may also include additive source 70 thatprovides one or more additives (e.g., the polymers, nanoparticles,and/or surfactants of the present disclosure, as well as other optionaladditives) to alter the properties of the fracturing fluid. For example,the other additives 70 can be included to reduce pumping friction, toreduce or eliminate the fluid's reaction to the geological formation inwhich the well is formed, to operate as surfactants, and/or to serveother functions.

The pump and blender system 50 receives the fracturing fluid andcombines it with other components, including optionally proppant fromthe proppant source 40 and/or additional fluid from the additives 70.The resulting mixture may be pumped down the well 60 under a pressuresufficient to create or enhance one or more fractures in a subterraneanzone, for example, to stimulate production of fluids from the zone.Notably, in certain instances, the fracturing fluid producing apparatus20, fluid source 30, and/or proppant source 40 may be equipped with oneor more metering devices (not shown) to control the flow of fluids,proppants, and/or other compositions to the pumping and blender system50. Such metering devices may permit the pumping and blender system 50can source from one, some or all of the different sources at a giventime, and may facilitate the preparation of fracturing fluids inaccordance with the present disclosure using continuous mixing or“on-the-fly” methods. Thus, for example, the pumping and blender system50 can provide just fracturing fluid into the well at some times, justproppants at other times, and combinations of those components at yetother times.

FIG. 2 shows the well 60 during a fracturing operation in a portion of asubterranean formation of interest 102 surrounding a well bore 104. Thewell bore 104 extends from the surface 106, and the fracturing fluid 108is applied to a portion of the subterranean formation 102 surroundingthe horizontal portion of the well bore. Although shown as verticaldeviating to horizontal, the well bore 104 may include horizontal,vertical, slant, curved, and other types of well bore geometries andorientations, and the fracturing treatment may be applied to asubterranean zone surrounding any portion of the well bore. The wellbore 104 can include a casing 110 that is cemented or otherwise securedto the well bore wall. The well bore 104 can be uncased or includeuncased sections. Perforations can be formed in the casing 110 to allowfracturing fluids and/or other materials to flow into the subterraneanformation 102. In cased wells, perforations can be formed using shapecharges, a perforating gun, hydro jetting and/or other tools.

The well is shown with a work string 112 depending from the surface 106into the well bore 104. The pump and blender system 50 is coupled a workstring 112 to pump the fracturing fluid 108 into the well bore 104. Theworking string 112 may include coiled tubing, jointed pipe, and/or otherstructures that allow fluid to flow into the well bore 104. The workingstring 112 can include flow control devices, bypass valves, ports, andor other tools or well devices that control a flow of fluid from theinterior of the working string 112 into the subterranean zone 102. Forexample, the working string 112 may include ports adjacent the well borewall to communicate the fracturing fluid 108 directly into thesubterranean formation 102, and/or the working string 112 may includeports that are spaced apart from the well bore wall to communicate thefracturing fluid 108 into an annulus in the well bore between theworking string 112 and the well bore wall.

The working string 112 and/or the well bore 104 may include one or moresets of packers 114 that seal the annulus between the working string 112and well bore 104 to isolate an interval of the well bore 104 into whichthe fracturing fluid 108 will be pumped. FIG. 2 shows two packers 114,one defining an uphole boundary of the interval and one defining thedownhole end of the interval. When the fracturing fluid 108 isintroduced into well bore 104 (e.g., in FIG. 2, the area of the wellbore 104 between packers 114) at a sufficient hydraulic pressure, one ormore fractures 116 may be created in the subterranean zone 102.Optionally, the proppant particulates in the fracturing fluid 108 mayenter the fractures 116 where they may remain after the fracturing fluidflows out of the well bore. These proppant particulates may “prop”fractures 116 such that fluids may flow more freely through thefractures 116. In some embodiments, multiple intervals in the same wellbore/formation may be isolated and treated successively in similarmanner.

While not specifically illustrated herein, the disclosed methods andcompositions may also directly or indirectly affect any transport ordelivery equipment used to convey the compositions to the fracturingsystem 10 such as, for example, any transport vessels, conduits,pipelines, trucks, tubulars, and/or pipes used to fluidically move thecompositions from one location to another, any pumps, compressors, ormotors used to drive the compositions into motion, any valves or relatedjoints used to regulate the pressure or flow rate of the compositions,and any sensors (i.e., pressure and temperature), gauges, and/orcombinations thereof, and the like.

To facilitate a better understanding of the present disclosure, thefollowing examples of certain aspects of certain embodiments are given.The following examples are not the only examples that could be givenaccording to the present disclosure and are not intended to limit thescope of the disclosure or claims.

EXAMPLES Example 1

Four fluid samples were each prepared by mixing 1 gpt of certainpolymers with water at ambient temperature. Samples 1 and 3(comparative) contained no additional additives. Samples 2 and 4additionally contained 0.1% v/v of clay nanotubes (provided as a drysolid) and 1 gpt of an anionic/nonionic/amphoteric surfactant. Theviscosity of each fluid was measured at ambient temperature using aFann® 35 viscometer at a shear rate of 511 s⁻¹. The water source,polymer, and viscosity of each fluid sample are reported in Table 1below.

TABLE 1 Fluid Viscosity Sample Water Polymer (cP) 1 Houston Anionicacrylamide/acrylic acid 4 tap copolymer 2 Houston Anionicacrylamide/acrylic acid 10 tap copolymer 3 Produced Cationicmultifunctional 2 water polyacrylamide 4 Produced Cationicmultifunctional 10 water polyacrylamideThis example demonstrates that the additives of the present disclosuremay impart enhanced viscosity to treatment fluids as compared withcertain other known friction reducing additives.

Example 2

Another fluid sample of the present disclosure (Sample 5) was preparedby mixing a much larger amount (3 gpt) of the anionic acrylamide/acrylicacid copolymer from Samples 1 and 2 in Houston tap water along with 0.5%v/v of Cloisite® 20A, a source of organophilic phyllosilicate claynanoparticles available from BYK USA, Inc. The viscosity of the fluidsample was measured ambient temperature using a Fann® 35 viscometer at ashear rate of 511 s⁻¹ at several intervals over a period of 15 minutes.Those measurements are reported in Table 2 below.

TABLE 2 Time Viscosity (min) (cP) 0 25 0.25 24.5 1 26.5 2 28.5 5 29.5 1029.5 15 29This example demonstrates that the additives of the present disclosuremay impart significant viscosity to a treatment fluid.

Example 3

Two fluid samples were each prepared as follows. Sample 6 (comparative)was prepared by mixing 1 gpt of a cationic polyacrylamide polymer and 1gpt of an amphoteric surfactant with a brine produced from a Marcellusshale formation. Sample 7 was prepared by mixing 0.5 gpt of theamphoteric surfactant from Sample 6 and 1 gpt of the cationicmultifunctional polyacrylamide from Samples 3 and 4 with a brineproduced from a Marcellus shale formation along with 0.1% v/v ofCloisite® 20A clay nanoparticles. The viscosities of these fluid sampleswere measured ambient temperature using a Fann® 35 viscometer at a shearrate of 511 s⁻¹ at several intervals over a period of 15 minutes. Thosemeasurements are reported in Table 3 below.

TABLE 3 Time Viscosity (cP) (min) Sample 6 Sample 7 0 15 13 0.25 14.5 121 14.5 12 2 15.5 12 5 17 11.5 10 16.5 11.5 15 16 11.5This example demonstrates that the additives of the present disclosuremay impart comparable or enhanced viscosity to treatment fluids ascompared with certain other known friction reducing additives, even whena lower concentration of polymer is used.

An embodiment of the present disclosure is a method that includes:providing a treatment fluid that includes an aqueous base fluid and afriction reducing additive, the friction reducing additive including atleast one polymer and a plurality of nanoparticles; and introducing thetreatment fluid into a portion of a subterranean formation at or above apressure sufficient to create or enhance at least one fracture in thesubterranean formation.

In one or more embodiments described in the preceding paragraph, thepolymer includes an anionic polymer. In one or more embodimentsdescribed above, the polymer includes a cationic polymer. In one or moreembodiments described above, the polymer includes an amphoteric polymer.In one or more embodiments described above, the polymer includes acationic acrylamide-based polymer. In one or more embodiments describedabove, the polymer includes at least one multifunctional polymer thatincludes one or more functional groups selected from the groupconsisting of: a choline group, a diallyldimethylammonium chloridegroup, and any combination thereof. In one or more embodiments describedabove, the polymer is present in the treatment fluid in an amount ofless than about 2 gallons per thousand gallons of the treatment fluid.In one or more embodiments described above, the aqueous base fluidincludes a brine. In one or more embodiments described above, theaqueous base fluid includes produced water. In one or more embodimentsdescribed above, the plurality of nanoparticles include at least onematerial selected from the group consisting of: silica, graphene, ametal, an alkaline earth metal, a metal oxide, boron, laponite, ahydroxide, a polymer, carbon, a clay, a composite material, and anycombination thereof. In one or more embodiments described above, theplurality of nanoparticles includes a plurality of functionalizednanoparticles. In one or more embodiments described above, the treatmentfluid further includes at least one surfactant. In one or moreembodiments described above, the treatment fluid has a viscosity of fromabout 4 cP to about 50 cP.

Another embodiment of the present disclosure is a method that includes:providing a treatment fluid that includes an aqueous base fluid and afriction reducing additive, wherein the friction reducing additiveincludes at least one polymer, a surfactant, and a plurality ofnanoparticles, and the treatment fluid has a viscosity of about 50 cP orless; and introducing the treatment fluid into a portion of asubterranean formation at or above a pressure sufficient to create orenhance at least one fracture in the subterranean formation.

In one or more embodiments described in the preceding paragraph, thepolymer includes an anionic polymer. In one or more embodimentsdescribed above, the polymer includes a cationic polymer. In one or moreembodiments described above, the polymer includes an amphoteric polymer.In one or more embodiments described above, the polymer includes acationic acrylamide-based polymer. In one or more embodiments describedabove, the polymer includes at least one multifunctional polymer thatincludes one or more functional groups selected from the groupconsisting of: a choline group, a diallyldimethylammonium chloridegroup, and any combination thereof. In one or more embodiments describedabove, the polymer is present in the treatment fluid in an amount ofless than about 2 gallons per thousand gallons of the treatment fluid.In one or more embodiments described above, the aqueous base fluidincludes a brine. In one or more embodiments described above, theaqueous base fluid includes produced water. In one or more embodimentsdescribed above, the plurality of nanoparticles include at least onematerial selected from the group consisting of: silica, graphene, ametal, an alkaline earth metal, a metal oxide, boron, laponite, ahydroxide, a polymer, carbon, a clay, a composite material, and anycombination thereof. In one or more embodiments described above, theplurality of nanoparticles includes a plurality of functionalizednanoparticles. In one or more embodiments described above, the pluralityof nanoparticles includes clay nanoparticles.

Another embodiment of the present disclosure is a method including:providing a treatment fluid that includes an aqueous base fluid and afriction reducing additive, wherein the friction reducing additiveincludes at least one acrylamide-based polymer, wherein theacrylamide-based polymer is present in an amount of less than about 2gallons per thousand gallons of the treatment fluid, a surfactant, and aplurality of clay nanoparticles; and introducing the treatment fluidinto a portion of a subterranean formation at or above a pressuresufficient to create or enhance at least one fracture in thesubterranean formation.

In one or more embodiments described in the preceding paragraph, thepolymer includes an anionic polymer. In one or more embodimentsdescribed above, the polymer includes a cationic polymer. In one or moreembodiments described above, the polymer includes an amphoteric polymer.In one or more embodiments described above, the polymer includes atleast one multifunctional polymer that includes one or more functionalgroups selected from the group consisting of: a choline group, adiallyldimethylammonium chloride group, and any combination thereof. Inone or more embodiments described above, the aqueous base fluid includesa brine. In one or more embodiments described above, the aqueous basefluid includes produced water. In one or more embodiments describedabove, the plurality of nanoparticles include at least one materialselected from the group consisting of: silica, graphene, a metal, analkaline earth metal, a metal oxide, boron, laponite, a hydroxide, apolymer, carbon, a clay, a composite material, and any combinationthereof. In one or more embodiments described above, the plurality ofnanoparticles includes a plurality of functionalized nanoparticles. Inone or more embodiments described above, the treatment fluid furtherincludes at least one surfactant. In one or more embodiments describedabove, the treatment fluid has a viscosity of from about 4 cP to about50 cP.

Therefore, the present disclosure is well adapted to attain the ends andadvantages mentioned as well as those that are inherent therein. Theparticular embodiments disclosed above are illustrative only, as thepresent disclosure may be modified and practiced in different butequivalent manners apparent to those skilled in the art having thebenefit of the teachings herein. While numerous changes may be made bythose skilled in the art, such changes are encompassed within the spiritof the subject matter defined by the appended claims. Furthermore, nolimitations are intended to the details of construction or design hereinshown, other than as described in the claims below. It is thereforeevident that the particular illustrative embodiments disclosed above maybe altered or modified and all such variations are considered within thescope and spirit of the present disclosure. In particular, every rangeof values (e.g., “from about a to about b,” or, equivalently, “fromapproximately a to b,” or, equivalently, “from approximately a-b”)disclosed herein is to be understood as referring to the power set (theset of all subsets) of the respective range of values. The terms in theclaims have their plain, ordinary meaning unless otherwise explicitlyand clearly defined by the patentee.

What is claimed is:
 1. A method comprising: providing a treatment fluidthat comprises an aqueous base fluid and a friction reducing additive,the friction reducing additive comprising at least one polymer and aplurality of nanoparticles; and introducing the treatment fluid into aportion of a subterranean formation at or above a pressure sufficient tocreate or enhance at least one fracture in the subterranean formation.2. The method of claim 1 wherein the polymer comprises an anionicpolymer.
 3. The method of claim 1 wherein the polymer comprises acationic polymer.
 4. The method of claim 1 wherein the polymer comprisesan amphoteric polymer.
 5. The method of claim 1 wherein the polymercomprises a cationic acrylamide-based polymer.
 6. The method of claim 1wherein the polymer comprises at least one multifunctional polymer thatcomprises one or more functional groups selected from the groupconsisting of: a choline group, a diallyldimethylammonium chloridegroup, and any combination thereof.
 7. The method of claim 1 wherein thepolymer is present in the treatment fluid in an amount of less thanabout 2 gallons per thousand gallons of the treatment fluid.
 8. Themethod of claim 1 wherein the aqueous base fluid comprises a brine. 9.The method of claim 1 wherein the aqueous base fluid comprises producedwater.
 10. The method of claim 1 wherein the plurality of nanoparticlescomprise at least one material selected from the group consisting of:silica, graphene, a metal, an alkaline earth metal, a metal oxide,boron, laponite, a hydroxide, a polymer, carbon, a clay, a compositematerial, and any combination thereof.
 11. The method of claim 1 whereinthe plurality of nanoparticles comprises a plurality of functionalizednanoparticles.
 12. The method of claim 1 wherein the treatment fluidfurther comprises at least one surfactant.
 13. The method of claim 1wherein the treatment fluid has a viscosity of from about 4 cP to about50 cP.
 14. A method comprising: providing a treatment fluid thatcomprises an aqueous base fluid and a friction reducing additive,wherein the friction reducing additive comprises at least one polymer, asurfactant, and a plurality of nanoparticles, and the treatment fluidhas a viscosity of about 50 cP or less; and introducing the treatmentfluid into a portion of a subterranean formation at or above a pressuresufficient to create or enhance at least one fracture in thesubterranean formation.
 15. The method of claim 14 wherein the pluralityof nanoparticles comprises clay nanoparticles.
 16. The method of claim14 wherein the polymer comprises at least one multifunctional polymerthat comprises one or more functional groups selected from the groupconsisting of: a choline group, a diallyldimethylammonium chloridegroup, and any combination thereof.
 17. The method of claim 14 whereinthe polymer is present in an amount of less than about 2 gallons perthousand gallons of the treatment fluid.
 18. A method comprising:providing a treatment fluid that comprises an aqueous base fluid and afriction reducing additive, wherein the friction reducing additivecomprises at least one acrylamide-based polymer, wherein theacrylamide-based polymer is present in an amount of less than about 2gallons per thousand gallons of the treatment fluid, a surfactant, and aplurality of clay nanoparticles; and introducing the treatment fluidinto a portion of a subterranean formation at or above a pressuresufficient to create or enhance at least one fracture in thesubterranean formation.
 19. The method of claim 18 wherein theacrylamide-based polymer comprises at least one multifunctionalacrylamide-based polymer that comprises one or more functional groupsselected from the group consisting of: a choline group, adiallyldimethylammonium chloride group, and any combination thereof. 20.The method of claim 18 wherein the treatment fluid has a viscosity ofabout 50 cP or less.